Method Of Utilizing Subterranean Formation Data For Improving Treatment Operations

ABSTRACT

Disclosed is a method in which subterranean formation data such as, but not limited to, pressure, mobility or permeability data is acquired while drilling and stored. The data is utilized to improve the design, the progress, and the evaluation of a subsequent wellbore treatment. The wellbore treatment may be conducted and monitored utilizing fiber optic enabled coiled tubing or the like.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of co-pending U.S. patent applicationSer. No. 13/996,514, filed Dec. 19, 2011, which is a 371 ofInternational Application No. PCT/US11/65720, filed Dec. 19, 2011, whichclaims benefit of U.S. Provisional Patent Application Ser. No.61/424,766, filed Dec. 20, 2010. Each of the aforementioned relatedpatent applications is herein incorporated by reference in its entirety.

BACKGROUND

The statements in this section merely provide background informationrelated to the present disclosure and may not constitute prior art.

The present disclosure is related to wellsite equipment and methods ofuse thereof, for example surface and downhole equipment used to developand/or produce an oilfield.

A wellbore may be formed by drilling into a subterranean formationcontaining a fluid or region of interest. Data may be acquired duringthe drilling operation as part of oilfield services including, but notlimited to, logging while drilling (LWD) services, measuring whiledrilling (MWD) services, and/or formation pressure while drilling (FPWD)services.

The life of the wellbore may subsequently include treatment operations,for example aimed at stimulating production of hydrocarbon fluids.

It remains desirable to provide improvements in oilfield surface anddownhole equipment and/or oilfield services.

SUMMARY

In an embodiment of a method usable in an oilfield, a wellbore isdrilled into a subterranean formation, data related to the subterraneanformation is acquired while drilling and stored, and a profile relatedto a property of the subterranean formation is calculated utilizing theacquired data. A treatment operation is performed in the wellbore. Datarelated to the treatment operation is measured and compared to theprofile. The treatment operation is improved based on the comparison.

In another embodiment of a method usable in an oilfield, a wellbore isdrilled into a subterranean formation, pressure data related to thesubterranean formation is acquired while drilling and stored, andinformation about the heterogeneity of the subterranean formation interms of transmissibility is estimated utilizing the pressure data. Atreatment operation is designed utilizing the estimated heterogeneity.The treatment operation is performed in the wellbore.

In an embodiment, the data acquired comprises formation permeabilitydata and/or fluid mobility data. In an embodiment, the data is acquiredwith a logging while drilling tool and/or a formation pressure whiledrilling tool having an extendable sample probe. In an embodiment, thedata related to the treatment operation comprises a remaining damage ofthe subterranean formation causing a skin effect. In an embodiment,calculating a profile comprises utilizing the acquired data to calculatean expected injection/production profile at an end of the treatmentoperation. In an embodiment, performing a treatment operation comprisesone of selecting an acid type and selecting a volume of acid utilizingthe acquired data and selecting may be based on information about theheterogeneity of the subterranean formation in terms oftransmissibility. In an embodiment, improving comprises adjustingtreatment fluid delivery based on the comparison of the measured data tothe profile.

In an embodiment, performing a treatment operation comprises performinga matrix acidizing operation and/or performing an operation with fiberoptic enabled coiled tubing and measuring may comprise measuring withthe fiber optic enabled coiled tubing and/or performing distributedtemperature sensing (DTS) with the fiber optic enabled coiled tubing. Inan embodiment, acquiring comprises acquiring one of formationpermeability data and fluid mobility data, and the method may furthercomprise evaluating the treatment operation by comparing DTS data withthe one of permeability data and fluid mobility data. The method mayfurther comprise gathering production data from the wellbore andcomparing the production data with one of the permeability data, thefluid mobility data, and the DTS data.

In an embodiment, the method may further comprise evaluating thetreatment operation using the profile and evaluating may comprisecomparing DTS data and production data.

In an embodiment, a method usable in an oilfield comprises drilling awellbore into a subterranean formation, acquiring and storing pressuredata related to the subterranean formation while drilling, estimatinginformation about the heterogeneity of the subterranean formation interms of transmissibility utilizing the acquired data, designing atreatment operation utilizing the estimated heterogeneity, andperforming the treatment operation in the wellbore. In an embodiment,selecting comprises one of selecting an acid type and selecting a volumeof acid. In an embodiment, the method further comprises calculating aprofile related to permeability of the subterranean formation utilizingthe acquired data.

BRIEF DESCRIPTION OF THE DRAWINGS

The features and advantages of the present disclosure will be betterunderstood by reference to the following detailed description whenconsidered in conjunction with the accompanying drawings wherein:

FIG. 1 is a schematic view of an embodiment of an apparatus forperforming a treatment operation of a subterranean formation inaccordance with the present disclosure;

FIGS. 2A and 2B are schematic views of an embodiment of a fiber opticenabled coiled tubing in accordance with the present disclosure; and

FIG. 3 is a flowchart of an example portion of a method of utilizingsubterranean formation data for subsequent treatment operation accordingto the present disclosure.

DETAILED DESCRIPTION

Indication of permeability heterogeneity of subterranean formations—thequality of variation in rock properties with location in a reservoir orsubterranean formations—would allow efficient selection of fluid systemsand volumes to be used during stimulation treatments of a wellboredrilled in the subterranean formations. When fluid mobility data (andformation permeability data) are computed from formation pressure datameasured while drilling the subterranean formations, the fluid mobilitydata (and formation permeability data) may be a good estimation of theflow properties of virgin or undamaged subterranean formation and maythus be used to indicate permeability heterogeneity of the subterraneanformations.

Further, prediction of post-treatment injectivity/productivity profileswould allow pro-active improvement of the delivery of the fluid systemsduring the stimulation treatment of the wellbore, for example byadapting the schedule of chemical diversion and matrix acidizingperformed with coiled tubing in carbonate formations. In hydrocarbonreservoirs where fluid mobility data (and formation permeability data)computed from formation pressure data acquired while drilling are wellcorrelated to post-treatment injectivity/productivity profiles measuredwith production logging tools (PLT), for example in some carbonateformations, the fluid mobility data (and formation permeability data)may also be used to predict injectivity/productivity profiles expectedafter formation damage is removed by the wellbore stimulation treatment(i.e., post-treatment injectivity/productivity profiles).

The present disclosure describes a method of utilizing subterraneanformation data for improving treatment operations. The method maycomprise acquiring pressure data while drilling with a formationpressure while drilling tool, for example the StethoScope tool, a markof Schlumberger Technology Corporation. The method may further comprisecomputing fluid mobility data (and formation permeability data) from thepressure data. The fluid mobility data (and formation permeability data)derived from formation pressure data acquired while drilling may beutilized for improving the efficiency of consequent wellbore treatmentsor treatment operations performed with coiled tubing, for example aspart of ACTive service, a service mark of Schlumberger Technologycorporation. The fluid mobility data (and formation permeability data)may be useful in the planning stages of a chemical diversion to beperformed prior to matrix acidizing stimulation, because formationheterogeneity may be a deciding factor in determining the fluid volumesrequired for chemical diversion. The fluid mobility data (and formationpermeability data) may additionally be useful during performing thematrix acidizing stimulation with fiber optic enabled coiled tubing,because comparison between actual injection/production profiles computedfrom distributed temperature surveys (DTS) and the predictedpost-treatment injection/production profiles may provide informationabout the effectiveness of the matrix acidizing stimulation as well asinformation about potential remaining damage potentially causing skineffect.

The heterogeneity indication and the post-treatment profile predictioncould alternatively be obtained from open hole log data (e.g., nuclearmagnetic resonance log data). Open hole logs provide information aboutporosity and fluid saturations, and there have been many attempts atcorrelating porosity (and fluid saturations) with formation permeability(and fluid mobility). But these correlations may fail in somehydrocarbon reservoir rocks, for example in carbonate formations. Incontrast to open hole log data, formation pressure data acquired whiledrilling a subterranean wellbore may provide relatively more reliablevalues of formation permeability (and fluid mobility).

As shown at 300 in FIG. 3, a drilling operation is performed, duringwhich time, such as when drilling is momentarily stopped, formationpressure data is acquired and stored. That is, a formation pressurewhile drilling (FPWD) tool is used to perform subterranean formationdrawdowns or pretests at locations along a wellbore drilled into thesubterranean formation. Those skilled in the art will appreciate thatother data may be acquired while drilling including, but not limited to,by logging while drilling (LWD) tools and/or services, measuring whiledrilling (MWD) tools and/or services, and the like.

In an embodiment, the FPWD tool may comprise a sample probe to drawfluid from the subterranean formation in order to determine variousproperties of the subterranean formation. The sample probe may beextendable with appropriate actuators in order to establish a fluidcommunication between the FPWD tool and the subterranean formation. TheFPWD tool may comprise suitable sensors, such as a pressure sensor, fordetermining the properties of the subterranean formation. The FPWD toolmay also comprise a suitable hydraulic assembly—including conduits,drawdown piston(s), and valve connections therebetween—in order toperform one or more drawdowns or pretests. One example implementation ofsuch a probe and hydraulic assembly is shown in U.S. Pat. No. 5,233,866,the disclosure of which is incorporated by reference herein in itsentirety.

Fluid mobility values—mobility of a fluid is the ratio of formationpermeability in millidarcies or and to the fluid viscosity in centipoiseor cp—may be computed from data acquired by the FPWD tool and stored bythe FPWD tool at 300. When formation pressure data are measured whiledrilling before significant subterranean formation damage occurs, or inabsence of skin effect, the data computed therefrom, including fluidmobility values, is a good estimation of the flow properties of virginor undamaged subterranean formation.

The formation pressure data acquired and stored at 300 may allow a userto calculate a zero skin fluid mobility profile (and a zero skinformation permeability profile). The calculated zero skin mobilityand/or permeability profile may then be used as a baselinerepresentative of the property of virgin or undamaged subterraneanformation in the planning stages of a wellbore treatment, as discussedin more detail below.

Further, the formation pressure while drilling data may be used tocalculate a zero skin injection/production data for the wellbore. Thecalculated zero skin injection/production data may then allow evaluationand/or pro-active improvement of the efficiency of the wellboretreatment, as discussed in more detail below. For example, using themobility values determined previously, a post-treatment cumulativeinjection/production capacitance curve may be predicted by summing theproduct of the mobility values by the spacing between the locationsalong the wellbore at which formation pressure measurements have beenperformed. The predicted post-treatment cumulative injection/productioncapacitance curve may be used as a baseline representative of acumulative injection/production capacitance curve that would be computedfrom measurements obtained post-treatment with a production logging tool(PLT).

After drilling the wellbore, formation damage may develop and may causea skin effect that is detrimental to the production of hydrocarbonfluids. As shown at 400 in FIG. 3, a treatment operation may be designedutilizing the data acquired and stored at 300, such as the calculatedzero skin fluid mobility profile (and formation permeability profile).In one example, data variations in the zero skin formation permeabilityprofile indicate the heterogeneity of the subterranean formation interms of fluid transmissibility, which may be subsequently utilized inthe design stage of fluid diversion to be conducted prior to astimulation treatment, such as matrix acidizing. Indication about theheterogeneity of the subterranean formation in terms of fluidtransmissibility may be useful in the planning stages of a wellboretreatment operation, as the amount of formation heterogeneity may be adeciding factor in determining the fluid volumes and/or the fluidviscosities required for chemical diversion or the like, as will beappreciated by those skilled in the art.

Thus, the acquired and stored formation pressure data may be used tocompute, for example, heterogeneity properties of the subterraneanformation which may in turn allow for the selection of the type andvolume of treatment fluid, such as, for example, diverter-acid fluidselection (e.g., based on diverter-acid fluid viscosity) anddiverter-acid fluid volumes (e.g., based on the extend of highpermeability zones along the wellbore) for use in stimulating acarbonate formation.

In addition, a provisional matrix acidizing schedule may be designed,based for example on past experience of subterranean formation damage,as will be appreciated by those skilled in the art.

As shown at 500 in FIG. 3, a treatment operation is conducted in asubterranean well, for example using coiled tubing services oroperations. The treatment operation may have been designed at 400.

Referring to FIG. 1, there is shown a schematic illustration ofequipment, and in particular surface equipment, used in providing coiledtubing services or operations in the subterranean well. The coiledtubing equipment may be provided to a well site using a truck 101, skid,or trailer. Truck 101 carries a tubing reel 103 that holds, spooled upthereon, a quantity of coiled tubing 105. One end of the coiled tubing105 terminates at the center axis of reel 103 in a reel plumbingapparatus 123 that enables fluids to be pumped into the coiled tubing105 while permitting the reel to rotate. The other end of coiled tubing105 is placed into wellbore 121 by injector head 107 via gooseneck 109.Injector head 107 injects the coiled tubing 105 into wellbore 121through the various surface well control hardware, such as blow outpreventer stack 111 and master control valve 113. Coiled tubing 105 mayconvey one or more tools or sensors 117 at its downhole end.

Coiled tubing truck 101 may be some other mobile-coiled tubing unit or apermanently installed structure at the wellsite. The coiled tubing truck101 (or alternative) also carries some surface control equipment 119,which may comprises a computer. Surface control equipment 119 isconnected to injector head 107 and reel 103 and is used to control theinjection of coiled tubing 105 into wellbore 121. Control equipment 119is also useful for controlling operation of tools and sensors 117 andfor collecting any data transmitted to from the tools and sensors 117 tothe surface. Monitoring equipment may also be provided together withcontrol equipment 119 or separately. The connection between coiledtubing 105 and monitoring equipment and or control equipment 119 may bea physical connection as with communication lines, or it may be avirtual connection through wireless transmission or known communicationsprotocols such as TCP/IP. In this manner, it is possible for monitoringequipment to be located at some distance away from the wellbore.Furthermore, the monitoring equipment may in turn be used to transmitthe received signals to offsite locations.

Turning to FIGS. 2A and 2B, there is shown cross-sectional views ofcoiled tubing apparatus 200 according to the present disclosure. Thecoiled tubing apparatus 200 includes a coiled tubing string 105, a fiberoptic tether 211 (comprising in the embodiment shown of an outerprotective tube 203 and one or more optical fiber 201), a surfacetermination 301, downhole termination 207, and a surface pressurebulkhead 213. Surface pressure bulkhead 213 is mounted in coiled tubingreel 103 shown in FIG. 1 and is used to seal fiber optic tether 211within coiled tubing string 105 thereby preventing release of treatingfluid and pressure while providing access to optical fiber 201. Downholetermination 207 provides both physical and optical connections betweenoptical fiber 201 and one or more optical tools or sensors 209. Opticaltools or sensors 209 may be the tools or sensors 117 of the coiledtubing operation shown in FIG. 1, may be a component thereof, or providefunctionality independent of the tools and sensors 117 that perform thecoiled tubing operations.

During the treatment, the coiled tubing string 105 is injected into thewellbore and a treatment fluid flows from the surface through theinterior 215 of the coiled tubing string 105 and into the wellbore 121.As will be appreciated by those skilled in the art, fiber optic enabledmeasurements, such as profiling with distributed temperature surveys(DTS), allows for injection profiles to be produced during the coiledtubing treatment. Fluid placement within the wellbore 121 may beimproved and/or optimized utilizing measurements enabled by the fiberoptic tether 211 disposed within the coiled tubing string 105, asdiscussed in more detail below.

Referring back to the method shown in FIG. 3, the treatment performed at500 may include pro-active improvement of the fluid systems and fluiddelivery with coiled tubing based on formation pressure data previouslyacquired in the subterranean well. For example, the zero skininjection/production data calculated at 300 may be used as a baseline topredict a post-treatment cumulative injection/production capacitancecurve. The distributed temperature surveys (DTS) obtained with fiberoptic in coiled tubing may be used to iteratively determine updatedcumulative injection/production capacitance curves. The updatedcumulative injection/production capacitance curves may be compared tothe predicted post-treatment cumulative injection/production capacitancecurve. Pro-active improvement of the fluid systems and fluid deliverymay be based on this comparison.

In an embodiment of the treatment performed at 500, by reducing orstopping the stimulation treatment in zones of the subterranean wellborewhere the updated cumulative injection/production capacitance curvematches the predicted post-treatment cumulative injection/productioncapacitance curve, over-stimulation may be reduced or avoided in thesezones. Thus, fluid placement may be improved.

In another embodiment of the treatment performed at 500, by increasingthe stimulation treatment in zones of the subterranean wellbore whereboth the updated cumulative injection/production capacitance curve doesnot match the predicted post-treatment cumulative injection/productioncapacitance curve and the zone transmissibility is still too low,under-stimulation may be reduced or avoided in these zones. For example,thief zones (other subterranean formation zones into which stimulationfluids may be lost) may prevent further stimulation in the mismatchzones. An operator may decide to inject chemical diversion fluid priorto resume injection of stimulation fluid. Thus, fluid treatment schedulemay be improved.

At 600, a post-treatment evaluation may be performed. The post-treatmentevaluation may include an indication of the agreement between the actualcumulative injection/production capacitance curve achieved at the end ofthe treatment performed at 500 and the predicted post-treatmentcumulative injection/production capacitance curve. The indication ofagreement may provide information about the effectiveness of thestimulation treatment. The post-treatment evaluation may compriseperforming a mini fall-off pressure analysis with pressure data recordedand transmitted while the coiled tubing is still in the well. The minifall-off pressure analysis may provide information about remainingdamage type, as will be appreciated by those skilled in the art. Thepost-treatment evaluation may also comprise utilizing the actualcumulative injection/production capacitance curve achieved at the end ofthe treatment performed at 500 to evaluate completion integrity, forexample to detect leaks through casing tubular.

After the treatments performed at 500 and the evaluations performed at600 are completed, the wellbore may be set up for producing orextracting hydrocarbon fluids therefrom. At various later points intime, perhaps even months or years, a production logging tool (PLT) orthe like may be utilized to gather data from the produced fluids. Thedata gathered with the PLT during production may be utilized to computea PLT profile. The PLT profile may be evaluated in order to, forexample, monitor the extent and/or type of the subterranean formationdamage by comparing the PLT profile to a corresponding profile computedfrom at least one of the subterranean formation data obtained at 300,the treatment data obtained at 500, and/or the post-treatment evaluationobtained at 600.

The preceding description has been presented with reference toparticular embodiments. Persons skilled in the art and technology towhich this disclosure pertains will appreciate that alterations andchanges in the described structures and methods of operation can bepracticed without meaningfully departing from the principle, and scopeof this description. Accordingly, the foregoing description should notbe read as pertaining (oily to the precise structures described andshown in the accompanying drawings, but rather should be read asconsistent with and as support for the following claims, which are tohave their fullest and fairest scope.

What is claimed is:
 1. A method usable in an oilfield, comprising:drilling a wellbore into a subterranean formation; acquiring and storingdata related to the subterranean formation while drilling; calculating aprofile related to a property of the subterranean formation utilizingthe acquired data; performing a treatment operation in the wellbore;measuring data related to the treatment operation; comparing themeasured data to the profile; and improving the treatment operationbased on the comparison.
 2. The method of claim 1 wherein acquiringcomprises acquiring one of formation permeability data and fluidmobility data.
 3. The method of claim 1 further comprising acquiringdata with a logging while drilling tool.
 4. The method of claim 1wherein acquiring comprises acquiring data with a formation pressurewhile drilling tool having an extendable sample probe.
 5. The method ofclaim 1 wherein the data related to the treatment operation comprises aremaining damage of the subterranean formation causing a skin effect. 6.The method of claim 1 wherein calculating a profile comprises utilizingthe acquired data to calculate an expected injection/production profileat an end of the treatment operation.
 7. The method of claim 1 whereinperforming comprises one of selecting an acid type and selecting avolume of acid utilizing the acquired data.
 8. The method of claim 7wherein selecting is based on information about the heterogeneity of thesubterranean formation in terms of transmissibility.
 9. The method ofclaim 1 wherein improving comprises adjusting treatment fluid deliverybased on the comparison of the measured data to the profile.
 10. Themethod of claim 1 wherein performing comprises performing a matrixacidizing operation.
 11. The method of claim 1 wherein performingcomprises performing an operation with fiber optic enabled coiledtubing.
 12. The method of claim 11 wherein measuring comprises measuringwith the fiber optic enabled coiled tubing.
 13. The method of claim 11wherein measuring comprises performing distributed temperature sensing(DTS) with the fiber optic enabled coiled tubing.
 14. The method ofclaim 11 wherein acquiring comprises acquiring one of formationpermeability data and fluid mobility data, the method further comprisingevaluating the treatment operation by comparing DTS data with the one ofpermeability data and fluid mobility data.
 15. The method of claim 14further comprising gathering production data from the wellbore andcomparing the production data with one of the permeability data, thefluid mobility data, and the DTS data.
 16. The method of claim 1 furthercomprising evaluating the treatment operation using the profile.
 17. Themethod of claim 16 wherein evaluating comprises comparing DTS data andproduction data.
 18. A method usable in an oilfield, comprising:drilling a wellbore into a subterranean formation; acquiring and storingpressure data related to the subterranean formation while drilling;estimating information about the heterogeneity of the subterraneanformation in terms of transmissibility utilizing the acquired data;designing a treatment operation utilizing the estimated heterogeneity;and performing the treatment operation in the wellbore.
 19. The methodof claim 18 wherein selecting comprises one of selecting an acid typeand selecting a volume of acid.
 20. The method of claim 18 furthercomprising calculating a profile related to permeability of thesubterranean formation utilizing the acquired data.